Wellbores are formed in subterranean formations for various purposes including, for example, extraction of oil and gas from the subterranean formation and extraction of geothermal heat from the subterranean formation. Wellbores may be formed in a subterranean formation using a drill bit such as, for example, an earth-boring rotary drill bit. Different types of earth-boring rotary drill bits are known in the art including, for example, fixed-cutter bits (which are often referred to in the art as “drag” bits), rolling-cutter bits (which are often referred to in the art as “rock” bits), diamond-impregnated bits, and hybrid bits (which may include, for example, both fixed cutters and rolling cutters). The drill bit is rotated and advanced into the subterranean formation. As the drill bit rotates, the cutters or abrasive structures thereof cut, crush, shear, and/or abrade away the formation material to form the wellbore. A diameter of the wellbore drilled by the drill bit may be defined by the cutting structures disposed at the largest outer diameter of the drill bit.
The drill bit is coupled, either directly or indirectly, to an end of what is referred to in the art as a “drill string,” which comprises a series of elongated tubular segments connected end-to-end that extends into the wellbore from the surface of the formation. Often various tools and components, including the drill bit, may be coupled together at the distal end of the drill string at the bottom of the wellbore being drilled. This assembly of tools and components is referred to in the art as a “bottom hole assembly” (BHA).
The drill bit may be rotated within the wellbore by rotating the drill string from the surface of the formation, or the drill bit may be rotated by coupling the drill bit to a downhole motor, which is also coupled to the drill string and disposed proximate the bottom of the wellbore. The downhole motor may comprise, for example, a hydraulic Moineau-type motor having a shaft, to which the drill bit is mounted, that may be caused to rotate by pumping fluid (e.g., drilling mud or fluid) from the surface of the formation down through the center of the drill string, through the hydraulic motor, out from nozzles in the drill bit, and back up to the surface of the formation through the annular space between the outer surface of the drill string and the exposed surface of the formation within the wellbore.
It is known in the art to use what are referred to in the art as “reamer” devices (also referred to in the art as “hole opening devices” or “hole openers”) in conjunction with a drill bit as part of a bottom hole assembly when drilling a wellbore in a subterranean formation. In such a configuration, the drill bit operates as a “pilot” bit to form a pilot bore in the subterranean formation. As the drill bit and bottom hole assembly advances into the formation, the reamer device follows the drill bit through the pilot bore and enlarges the diameter of, or “reams,” the pilot bore.
The bodies of downhole tools, such as drill bits and reamers, are often provided with fluid courses, such as “junk slots,” to allow drilling mud (which may include drilling fluid and formation cuttings generated by the tools that are entrained within the fluid) to pass upwardly around the bodies of the tools into the annular space within the wellbore above the tools outside the drill string. Drilling tools used for casing and liner drilling usually have smaller fluid courses and are particularly prone to balling, causing a lower rate of penetration.
When drilling a wellbore, the formation cuttings may adhere to, or “ball” on, the surface of the drill bit. The cuttings may accumulate on the cutting elements and the surfaces of the drill bit or other tool, and may collect in any void, gap, or recess created between the various structural components of the bit. This phenomenon is particularly enhanced in formations that fail plastically, such as in certain shales, mudstones, siltstones, limestones and other relatively ductile formations. The cuttings from such formations may become mechanically packed in the aforementioned voids, gaps, or recesses of the drill bit. In other cases, such as when drilling certain shale formations, the adhesion between formation cuttings and a surface of a drill bit or other tool may be at least partially based on chemical bonds therebetween. When a surface of a drill bit becomes wet with water in such formations, the bit surface and clay layers of the shale may share common electrons. A similar sharing of electrons is present between the individual sheets of the shale itself. A result of this sharing of electrons is an adhesive-type bond between the shale and the bit surface. Adhesion between the formation cuttings and the bit surface may also occur when the charge of the bit face is opposite the charge of the formation. The oppositely charged formation particles may adhere to the surface of the bit. Moreover, particles of the formation may be compacted onto surfaces of the bit or mechanically bonded into pits or trenches etched into the bit by erosion and abrasion during the drilling process.
In some cases, drilling operations are conducted with reduced or mitigated hydraulics. For example, some rigs may not have large pumps for drilling to the depths required. Furthermore, operators sometimes find it too costly to run higher mud flow rates or find that high flow rates cause more wear and tear to the BHA. Drilling with reduced or mitigated hydraulics has a tendency to cause balling.
Attempts have been made to reduce the likelihood of balling in downhole tools, as disclosed in, for example, U.S. Pat. No. 5,651,420, which issued Jul. 29, 1997, to Tibbitts et al., and U.S. Pat. No. 6,260,636, which issued Jul. 17, 2001, to Cooley et al.; and U.S. Pat. No. 6,450,271, which issued Sep. 17, 2002, to Tibbitts et al.